Method and apparatus to increase recovery of hydrocarbons

ABSTRACT

Methods for enhancing the extraction of fluids from subterranean formation through wells using hydrogen produced in-situ. Certain embodiments produce hydrogen in-situ through reactions of a hydride. In one embodiment, at least a portion of the produced hydrogen is retained in the well bore for a sufficient amount of time to allow hydrogen to migrate into the subterranean formation. In certain embodiments, in absorbing the hydrogen, the subterranean formation desorbs and releases certain organic material for production through a well bore. In other embodiments, the subterranean formation is placed under pressure to drive the hydrogen further into the formation and into the molecular structure of the formations and substances contained therein. When pressure is released, the hydrogen creates additional fractures or cracks in the formation through explosive compression, thereby increasing permeability of the formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent ApplicationNo. 61/612,560, filed Mar. 19, 2012 entitled, “METHOD AND APPARATUS TOINCREASE RECOVERY OF HYDROCARBONS,” and U.S. Provisional PatentApplication No. 61/626,684, filed Oct. 3, 2011; and U.S. ProvisionalPatent Application No. 61/628,535, filed Nov. 2, 2011; and thedisclosure of which are incorporated herein by reference.

TECHNICAL FIELD

Embodiments of the present invention are generally directed to methodsand apparatus to extract substances from subterranean depths and morespecifically to enhancing the extraction and transformation ofsubstances from subterranean strata by altering the subterranean stratawith hydrogen. Embodiments of the present invention are particularlyapplicable to the extraction and or transformation of hydrocarbons, butthey are also applicable to the extraction of other gases and mineralsfrom any subterranean depth.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present invention.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presentinvention. Accordingly, it should be understood that this section shouldbe read in this light, and not necessarily as any admission of priorart.

To extract substances from subterranean strata below the surface of theearth, it is typically desirable to drill well bores into the earth fromthe surface to house conduits that transfer substances between thesurface and the subterranean strata to extract substances from thesubterranean strata. The oil and gas industry often uses hydraulicfracturing methods to enhance the recovery of in-situ hydrocarbonsubstances. A common method is to pump high pressure fluids from thesurface into subterranean strata to fracture, break, and/or rubblize thesubterranean strata to enhance the subterranean strata's fluidconductivity, thereby allowing more hydrocarbons to flow to the wellbore. One conventional hard rock mining technique often involvesrubblizing the strata by placing explosives in the wellbore to alter thestrata around the wellbores when the explosives are activated.

Subterranean non-organic substances that are typically extracted usingwell bores in the mining process include noble metals such as gold,silver, platinum, palladium, and other minerals such as rare earths,thorium, and uranium. Subterranean organic substances that are typicallyextracted using well bores often include fluid substances, such as oil,bitumen, kerogen, and natural gas, and solid substances such as coal.The particular subterranean reservoirs or strata containing thesubterranean fluid substances often do not have sufficient energy toprovide the requisite fluid conductivity to drive such fluids into awellbore for transfer to the surface of the earth. Fluid permeability ofa given strata is often measured by those familiar to the art of oil andgas industry extraction in units of Darcy's. The known reservoirs thatare pool-like such as Saudi Arabia, Prudoe Bay, Lake Meraciabo, and manyothers had permeability in the order of Darcy or milli-Darcy. Today'sunconventional sand and shale discoveries in the United States oftenhave permeability in the ranges from micro to nano-Darcy permeabilityand below. Therefore, what is needed is new extraction methods for theseunconventional hydrocarbon reservoirs like shales, tight gas sands, coalbed methane reservoirs, diatomaceous deposits, and siltstones, whichhave ultra-low permeability.

SUMMARY

Embodiments of the present invention provide for the extraction ofsubterranean substances to the surface and or transformation ofsubterranean substances with hydrogen placed in-situ with hydraulicfracture methods. Certain embodiments of the present invention providefor use of hydrogen in-situ for enhancing the recovery of hydrocarbonsfrom very low permeability strata having permeability in the ranges ofmicro-Darcy and nano-Darcy, such as the oil shale deposits, tightnatural gas sands, gas shales, tar sands, bitumen deposits, coaldeposits, kerogen accumulations in oil shales, as well as othernon-organic minerals. Embodiments of this invention have furtherapplications for the recovery of other subterranean minerals such asrare earths, copper, gold, uranium, and coal to the surface of theearth.

According to one aspect of the present invention, a method for theextraction of substances from a subterranean formation is described. Themethod comprises the steps of (a) injecting a first fluid system into asubterranean formation through a wellbore at a pressure sufficient tocreate at least one fracture in the subterranean formation, where thesubterranean formation is in fluid communication with the wellbore; (b)injecting a second fluid system into the subterranean formation throughthe wellbore, where the second fluid system comprises a hydridesubstance; (c) mixing, in the wellbore, at least a portion of the firstfluid system with at least a portion of the hydride material of thesecond fluid system to produce hydrogen; (d) retaining at least aportion of the produced hydrogen in the subterranean formation for aperiod of time of at least 10 hours; and (e) after the period of time ofretention, producing at least one substance from the subterraneanformation to the surface.

In one embodiment, the hydride substance preferably comprises a metalhydride substance. In another embodiment, the first fluid system andsecond fluid system are injected into the wellbore simultaneously. Inanother embodiment, the at least one substance from the formation isproduced through a wellbore. In another embodiment, the productionwellbore is the wellbore used for the injection of the first fluidsystem and said second fluid system. In another embodiment, the firstfluid system is injected into the wellbore using a first conduit andsaid second fluid system is injected into the wellbore using a secondconduit separate from the first conduit. In another embodiment, thesecond conduit is disposed in the first conduit through at least aportion of the wellbore. In yet another embodiment, the first conduitcomprises a well casing and the second conduit comprises a coiled tubingdisposed in the well casing.

In one embodiment, at least one of the first fluid system and secondfluid system has a pH less than about 7. In another embodiment, thesecond fluid system has a pH of about 7 or greater. In anotherembodiment, the method further comprises a step of heating the firstfluid system to a temperature greater than the surface ambienttemperature prior to injecting it into the wellbore. In anotherembodiment, the first fluid system comprises at least one of thefollowing: steam, carbon dioxide, water, nitrogen, a hydride catalyst, ahydride retarder, and any combination thereof. In one embodiment, thehydride catalyst comprises cobalt. In one embodiment, the hydrideretarder comprises a substance configured to coat the hydride uponcontact with said hydride. In yet another embodiment, the second fluidsystem has a pH of about 7 or greater, the second fluid system comprisesat least one of the following: an ammoniated fluid, ammonia hydroxide,and any combination thereof. In one embodiment, the second fluid systemcomprises at least one of the following: a hydrocarbon, a hydridereaction stabilizer, and an alcohol.

In one embodiment, the first fluid system and second fluid system arealternatively injected into the wellbore. In another embodiment, thefirst fluid system comprises a previously recovered subterranean fluidproduced from the subterranean formation. In one embodiment, an injectedfluid comprises at least one of the following: carbon dioxide, water,and any combination thereof. In one embodiment, at least one of saidfirst fluid system and second fluid system contains at least one of thefollowing: a propping agent, a fluid viscosity modifier, a surfacetension reducing agent, a micro-emulsion, and any combination thereof.In one embodiment, the viscosity modifier is a gelling agent. In oneembodiment, the gelling agent comprises a pH less than 7. In anotherembodiment, the respective fluid comprising the propping agent has a pHless than about 7.

In one embodiment, the step of retaining a portion of said hydrogencomprises retaining at least a portion of the hydrogen in the formationunder pressure. In one embodiment, the pressure is held from thesurface. In another embodiment, the pressure is held from below surface.In another embodiment, the method further comprises the step ofreleasing at least a portion of the pressure from the formation. In oneembodiment, the release of pressure causes explosive decompression of atleast a portion of the formation.

In one embodiment, at least a portion of the hydrogen of said hydridereaction is produced to surface. In another embodiment, the hydridecomprises at least one of the following: sodium borohydride, potassiumborohydride, and lithium borohydride. In another embodiment, the hydridecan comprise a solid substance or a solution. In another embodiment, thehydride substance comprises a blend of different hydrides. In anotherembodiment, the production of hydrogen is further assisted by geothermalenergy from said formation. In yet another embodiment, the methodfurther comprises the steps of absorbing by said formation at least aportion of the retained hydrogen; and in response to said absorption,desorbing at least one substance from the formation. In anotherembodiment, the at least one subterranean substance is produced througha second well bore separate from the well bore provided for injection ofthe first and second fluid systems.

According to another aspect of the invention, a method to enhance therecovery of at least one subterranean substance by decompressing atleast a portion of a subterranean formation is described. The methodcomprises the steps of a) injecting at least one fluid system comprisinga hydride into a subterranean formation through a wellbore, wherein thesubterranean formation is in fluid communication with the wellbore; b)producing hydrogen in-situ from a chemical reaction of at least aportion of the hydride; c) retaining at least a portion of the producedhydrogen in the subterranean formation for at least 10 hours; d)increasing pressure of the formation at least through the hydrogenproduction and retention; e) releasing at least a portion of pressurefrom the subterranean formation; 0 recovering to surface at least onesubterranean substance from the subterranean formation through awellbore.

In one embodiment the at least one fluid system comprises at least oneof the following: carbon dioxide, steam, nitrogen, carbon monoxide, andany combination thereof. In another embodiment, the method furthercomprises the step of injecting an additional fluid system into thewellbore prior to the step of injecting the at least one fluid system.In another embodiment, the additional fluid system is injected at apressure above hydraulic fracture pressure. In another embodiment, themethod further comprises injecting an additional fluid system into thewellbore after the step of injecting the at least one fluid system,wherein the additional fluid system is injected at a pressure belowhydraulic fracture pressure. In one embodiment, the additional fluidsystem comprises at least one of the following: an acid, carbon dioxide,an ammoniated fluid, steam, a hydride retarder, and any combinationthereof. In another embodiment, at least one of the at least one fluidsystem and additional fluid system comprises a hydride catalyst. Inanother embodiment, the pressure is released from the well allowing atleast a portion of the in-situ generated hydrogen to flow out of saidsubterranean formation. In another embodiment, the pressure release isdone rapidly from surface to force explosive decompression of at least aportion of hydrogen in said subterranean formation. In yet anotherembodiment, the method further comprises the step of placing a packer insaid wellbore at a position near where said at least one fluid system isintroduced to the subterranean formation, said packer is configured torelease at least a portion of pressure in the subterranean formation.

According to another aspect of the present invention, a method ofrecovering at least one subterranean substance from a subterraneanformation with hydrogen is described. The method comprises the steps ofa) injecting, through at least one conduit disposed in a first wellbore,at least a portion of one fluid system from surface into a subterraneanformation in fluid communication with the wellbore; b) injecting atleast one additional fluid system into the subterranean formation, theat least one additional fluid system comprising a hydride; c) releasingat least a portion of hydrogen released from said hydride in the atleast one additional fluid system by mixing the at least one fluidsystem with the at least one additional fluid system in-situ; d)allowing at least a portion of the hydrogen to enter the subterraneanformation; and e) recovering at least one substance contained in thesubterranean formation to the surface through a second wellbore.

In one embodiment, at least one fluid system comprises at least one ofthe following: carbon dioxide, a hydride catalyst, a reactive substanceconfigured to liberate hydrogen from said hydride substance, and water.In another embodiment, the fluid systems are injected in alternatingstages. In another embodiment, the at least one fluid system has a pH ofabout 7 or less. In another embodiment, the at least one additionalfluid system comprising hydride has a pH of about 7 or greater. Inanother embodiment, the recovering back to surface said subterraneansubstances comprises removing at least a portion of said subterraneanformation and transferring said portion to surface. In anotherembodiment, the at least one substance contained in said subterraneanformation comprises hydrocarbons. In another embodiment, the at leastone substance contained in said subterranean formation comprises atleast one rare earth substance.

According to another aspect of the present invention, a method for theextraction of substances from subterranean formation is described. Themethod comprises the steps of (a) injecting at least one fluid systemsfrom the surface of the earth through at least one conduit disposed in afirst wellbore into a subterranean formation at a pressure sufficient tohydraulically fracture the subterranean formation; (b) injecting atleast one additional fluid system comprising hydrogen; (c) exposing thesubterranean formation to at least a portion of the hydrogen byretaining at least a portion of the hydrogen in the subterraneanformation for more than 10 hours; (d) releasing at least a portion ofpressure in the subterranean reservoir; and (e) recovering back tosurface at least one substance disposed in said subterranean formation.

In one embodiment, the retaining step comprises holding at least aportion of the subterranean reservoir under hydrostatic pressure. Inanother embodiment, the recovering step to surface is performed throughat least one well bore. In another embodiment, the recovering step isperformed through removal of at least a portion of the subterraneanformation containing the at least one substance.

According to another aspect of the present invention, a method oftransforming in-situ substances in subterranean formation with hydrogenand producing said substances to surface is described. The methodcomprises the steps of (a) injecting at least one fluid system throughat least one conduit disposed in a first wellbore into a subterraneanformation in fluid communication with at least the first wellbore; (b)injecting at least one additional fluid system into the subterraneanformation, the at least one additional fluid system comprising ahydride; (c) creating a reaction with said hydride to release hydrogencontained in at least a portion of the hydride; (d) retaining at least aportion of the released hydrogen in said subterranean formation for atleast 10 hours; (e) allowing at least a portion of the hydrogen totransform at least a portion of a substance contained in thesubterranean formation; and (f) producing to surface at least a portionof the transformed substance contained in the subterranean formation. Inone embodiment, the producing step occurs through a second wellbore.

The foregoing has outlined rather broadly the features and technicaladvantages of the present disclosure in one specific field ofunderground mining, commonly known as the field of upstream oil and gasrecovery from wells, in order that the detailed description of thisdisclosures mining and in-situ processing that follows may be betterunderstood. It is understood that this disclosures methods of placinghydrogen at subterranean depths can be used in other fields of miningsubstances from the earth to hydrolyze, crack, rubblizing or otherwiseenhance the commercialization of other substances from below the surfaceof the earth. Additional features and advantages of the disclosure willbe described hereinafter which form the subject of the claims of thedisclosure. It should be appreciated by those skilled in the art of oiland gas recover or underground mining, that the conception and specificembodiment disclosed of placing hydrogen in subterranean environmentsmay be readily utilized as a basis for modifying or designing otherstructures, substances, and processes for carrying out the same purposesof the present disclosure. It should also be realized by those skilledin the art that such equivalent constructions, substances, methods,processes, or apparatus do not depart from the spirit and scope of thedisclosure as set forth in the appended claims. The novel features whichare believed to be characteristic of the disclosure, both as to itsorganization and method of operation, together with further objects andadvantages will be better understood from the following description whenconsidered in connection with the accompanying figures. It is to beexpressly understood, however, that each of the figures is provided forthe purpose of illustration and description only and is not intended asa definition of the limits of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the embodiments of the presentinvention, reference is now made to the following descriptions taken inconjunction with the accompanying drawing, in which:

FIG. 1 illustrates an exemplary embodiment of a production systememploying certain aspects of the present invention to enhance productionof subterranean substances;

FIG. 2 illustrates an exemplary effect of implementing certaintechniques of the present invention to enhance production ofsubterranean substances;

FIG. 3 illustrates another exemplary effect of implementing certaintechniques of the present invention to enhance production ofsubterranean substances; and

FIG. 4 illustrates another exemplary embodiment of a production systememploying certain aspects of the present invention to enhance productionof subterranean substances from multiple wellbores.

It should be understood that the drawings are not necessarily to scaleand that the disclosed embodiments are sometimes illustrateddiagrammatically and in partial views. In certain instances, detailswhich are not necessary for an understanding of the disclosed methodsand apparatuses or which render other details difficult to perceive mayhave been omitted. Also, for simplification purposes, there may be onlyone exemplary instance, rather than all, is labeled. It should beunderstood, of course, that this disclosure is not limited to theparticular embodiments illustrated herein.

DETAILED DESCRIPTION OF THE DISCLOSURE

As used herein, “a” or “an” means one or more. Unless otherwiseindicated, the singular contains the plural and the plural contains thesingular. Where the disclosure refers to “perforations” it should beunderstood to mean “one or more perforations.”

As used herein, “surface” refers to locations at or above the surface ofthe earth, whether that surface is covered with water or not.

As used herein, “hydraulic fracturing” refers to the method of injectinga fluid above the fracture pressure of a subterranean reservoir intowhich the fluid is injected.

As used herein, “matrix stimulation” refers to the method of injection afluid below the hydraulic fracture pressure of the reservoir in whichthe fluid is injected.

As used herein “propping” agent refers to any solid material that hassubstantial strength to resist the overburden forces of the earth in thereservoir wherein it is pumped.

As used herein “fluid system” refers to fluids that contain chemicals,catalyst, and/or propping agents.

As used herein “conduit” refers to a path that allows for transmissionof fluid and any pressure of such fluid.

As used herein “ strata,” “stratum,” or “formation” includes aparticular depth or various depths below the surface of the earth ofsolids, liquids, and gas constituents that comprise the earth.

As used herein the term “reservoir” includes a deposit of substances insubterranean strata.

As used herein “fluids” is defined as any liquid, plasma, gas orsubstance that deforms under shear stress.

Embodiments of the present invention provide a method to improveproduction of subterranean substances from subterranean formations thathave permeability in the ranges of nano-Darcy to micro-Darcy, which theconvention hydraulic methods are not as effective at improvingpermeability as reservoir-like formations with permeability in themilli-Darcy to Darcy range. In one embodiment, the method to enhanceproduction of the present invention fractures or transforms thesubterranean formation or strata using molecular cracking mechanisms.Certain embodiments of the present invention provide fracturing of thesubterranean formation having low permeability to fluid flow usingmaterial that is environmentally safer than the substances used inconventional hydraulic fracturing process.

In one embodiment, the method to enhance production of the presentinvention uses hydrogen that is generated in the subterraneanenvironment to modify the properties of formation fluid and to furtherincrease the permeability of the subterranean formation by molecularlycracking and desorbing hydrocarbons. In another embodiment, the methodto enhance production of the present invention uses an energizing fluidthat, if flowed back from the reservoir, it can be sold directly withthe hydrocarbon fluids produced from the reservoir.

Attention is first directed to FIG. 1, which shows a preferredembodiment of injection system 100 implementing certain aspects of thepresent invention. Referring to FIG. 1, there is well casing 1 that isdisposed in wellbore 2. In a preferred embodiment, well casing 1 is aconduit that provides at least a path for fluid transmission between thesurface and subterranean formation 4. In another embodiment, wellbore 2may not include any well casing such that wellbore 2 itself or otherconduits that can be removably inserted serves as the conduit providinga path for fluid transmission between the surface and subterraneanformation 4. Well casing 1 and wellbore 2 preferably have perforations 3that provide fluid communication between well casing 1 and formation 4,allowing fluids to flow from well casing 1 to subterranean formation 4,such as during an injection stage, or vice versa, allowing fluids toflow into well casing 1 from subterranean formation 4, such as duringproduction of formation substances to the surface. In a preferredembodiment, injection system 100 further includes tank components 5, 10,and 11 preferably in fluid communication with well casing 1. In oneembodiment, tank components 10 and 11 each preferably contains firstfluid system 12, and tank component 5 preferably contains second fluidsystem 9. In a preferred embodiment, both first fluid system 12 andsecond fluid system 9 are introduced to subterranean formation 4 byinjecting both fluid systems 12, 9 into well casing 1. First fluidsystem 12 is preferably used for hydraulic fracturing of subterraneanformation 4 where first fluid system 12 is injected at a pressure abovethe fracture pressure of subterranean formation 4. In a preferredembodiment, first fluid system 12 in tank components 10, 11 comprises awater gel solution configured for hydraulic fracturing of subterraneanformation 4. In one embodiment, first fluid system 12 has a pH of lessthan about 7. In another embodiment, first fluid system 12 has a pH ofabout 7 or greater. In yet another embodiment, first fluid system 12 isheated to a temperature greater than the surface ambient temperatureprior to its injection into well casing 1.

Referring to FIG. 1, in a preferred embodiment, second fluid system 9preferably comprises a hydride substance, more preferably a metalhydride substance. Preferably, the introduction of second fluid system 9to first fluid system 12 causes a chemical reaction that produceshydrogen. In a preferred embodiment, the chemical reaction involves thehydride, and preferably metal hydride, in second fluid system 9.Referring to FIG. 1, in a preferred embodiment, both fluid systems 12, 9are kept separate from each other through at least a portion of wellcasing 1 to prevent them from mixing with one another prematurely. Thetwo fluid systems 12, 9 are preferably combined or mixed nearperforations 3. In one embodiment, second fluid system 9 can includeammonia hydroxide, or a metal hydride hydrocarbon fluid system. Inanother embodiment, second fluid system 9 can have a pH of less thanabout 7, about 7, or greater than 7. In an embodiment where second fluidsystem 9 comprises a base, it preferably comprises ammoniated fluid,ammonia hydroxide, and anhydrous ammonia. In an embodiment containinghydride, the hydride in second fluid system 9 comprises at least one ofthe following: sodium borohydride, potassium borohydride, and lithiumborohydride. In one embodiment, the hydride comprises a solid substance.In another embodiment, the hydride comprises a solution. In anotherembodiment, the hydride comprises a blend of different hydrides,particularly metal hydrides. In another embodiment, second fluid system9 further includes at least one of the following alcohol, a hydrocarbon,a hydride stabilizer.

Referring to FIG. 1, in one preferred embodiment, tank component 5 isfluidly coupled to well casing 1 using coiled tubing 6 that can belowered into well casing 1 through coiled tubing injector head 7 coupledto well casing 1, where coiled tubing injector head 7 is preferablysupported by crane 17. Preferably, coiled tubing 6 is another conduitthat provides at least a path for fluid transmission between the surfaceand subterranean formation 4. In a preferred embodiment, pump component8 is used to inject second fluid system 9 into coiled tubing 6 forinjection into well casing 1. Preferably, coiled tubing 6 can be placedat any desired depth in well casing 1, allowing for the desiredplacement of where second fluid 9 is introduced into well casing 1, aswell as the desired placement of where fluid systems 12, 9 are mixedwith one another conduit that provides at least a path for fluidtransmission between the surface and subterranean formation 4. Othermeans known to one of ordinary skill in the art can be used as a secondconduit that provides at least a path for fluid transmission between thesurface and subterranean formation 4, such as for injection of secondfluid system 9 into well casing 1.

Referring to FIG. 1, in a preferred embodiment, injection system 100further includes blender truck unit 13 fluidly coupled to tankcomponents 10 and 11 to combine first fluid system 12 from both tankcomponents 10 and 11. Injection system 100 preferably includes proppingagent transport truck 15 that adds propping agent 14, preferably aproppant known to one of ordinary skill in the art for use in hydraulicfracturing, to blender truck unit 13, which is configured to combinepropping agent 14 to first fluid system 12. Blender truck unit 13 ispreferably adapted to combine other materials with first fluid system 12that are added to blender truck unit 13. In one embodiment, proppingagent 14 and first fluid system 12 have a pH of less than about 7. In apreferred embodiment, the mixture of first fluid system 12 and proppant14 in blender truck unit 13 can be injected directly into casing 1.

In another embodiment, injection system 100 is adapted to heat at leastone of second fluid system 9, first fluid system 12, and any other fluidcomponent used to a temperature greater than the surface ambienttemperature. One exemplary way to raise the temperature of first fluid12 is to add steam to blender truck unit 13. Other gas can also be addedto blender truck unit 13, such as nitrogen, carbon dioxide, or carbonmonoxide. Other additives can also be added to first fluid system 12 inblender truck unit 13, such as water, a surface tension reducing agent,a scale inhibitor, a micro-emulsion, a hydride catalyst, a hydrideretarder. An exemplary embodiment of a hydride catalyst is cobalt. Anexemplary embodiment of a hydride retarder is a coating for a hydride.The hydride catalyst and/or retarder are preferably selected based onthe particular temperature of the area in well casing 1 aroundsubterranean formation 4. Other additives can also be added to firstfluid system 12 in blender truck unit 13, such as, but not limited to,stabilizers and frac chemicals known to those familiar with the art ofhydraulic fracturing, including pH adjusters, cross linkers,surfactants, breakers, tracers, and any combination thereof. In oneembodiment, first fluid system 12 can include a previously recoveredsubterranean fluid, more preferably produced from subterranean formation4. The previously recovered fluid can include carbon dioxide, water, orany combination thereof. Blender truck unit 13 can further add to andmix other fluids with first fluid system 12 for injection such as afluid viscosity modifier, such as a gelling agent, preferably having apH of less than 7. It is understood that any of the additives ormaterials added to blender truck unit 13 can also be added, as analternative or addition, to second fluid system 9 as appropriate.

In a preferred embodiment, once first fluid system 12, proppant 14, andany additional additives are sufficiently mixed, first fluid system 12in blender truck unit 13 is transferred to at least one high pressurepump truck, such as high pressure pump truck 16, to be injected intowell casing 1. Referring to FIG. 1, in a preferred embodiment, firstfluid system 12 in blender truck unit 13 is injected into well casing 1through an opening at the side of well casing 1 above the surface.

According to another aspect of the present invention, there is provideda method of enhancing production in low permeability formations usinginjection system 100. Referring to FIG. 1, in a preferred embodiment,first fluid system 12 from tank components 10 and 11, proppant 14 fromproppant dump truck 15, and any desired additives are added to blendertruck unit 13 for mixing. At any point in time, coiled tubing 6 can belowered through coiled tubing injector head 7 and preferably lowered toa position near perforations 3 in well casing 1. In a preferredembodiment, at least the location of the open end of coiled tubing 6helps to determine the location of the mixing point of first fluidsystem 12 and second fluid system 9. The mixing point is preferablybelow the surface near perforations 3. Once blender truck unit 13 hassufficiently mixed the substances therein, both first fluid system 12 inblender truck unit 13 and second fluid system 9 from tank component 5are preferably simultaneously injected into well casing 1. In anotherembodiment, first fluid system 12 in blender truck unit 13 and secondfluid system 9 are each injected in an alternating manner. Referring toFIG. 1, in a preferred embodiment, first fluid system 12 in blendertruck unit 13 is injected into well casing 1 with pump truck 16, andsecond fluid system 9 is injected into well casing 1 through coiledtubing 6 with pump 8. In a preferred embodiment, first fluid system 12is injected at a pressure sufficient to hydraulically fracturesubterranean formation 4. In another embodiment, at least one of thefluid systems 12, 9 is injected to provide matrix stimulation, e.g.,injected at a pressure below the hydraulic facture pressure of formation4.

In one embodiment, injection of first fluid system 12 containing varioussubstances and second fluid system 9 produces hydraulic fractures 18 insubterranean formation 4. Second fluid system 9 and first fluid system12, which can contain additives, like catalyst, retarders,cross-linkers, surfactants, pH adjusters, are preferably mixed in wellcasing 1 below the surface and transferred out into the subterraneanformation 4 through well perforations 3 and into fractures 18. Once thehydraulic fracture injection of first fluid system 12 and second fluidsystem 9 is completed, coiled tubing 6 is preferably pulled from wellcasing 1. Upon being introduced to one another, first fluid system 12and second fluid system 9 react with one another to produce hydrogen 20.Preferably, the hydride in second fluid system 9 reacts with certainsubstances in first fluid system 12 to produce hydrogen 20. In apreferred embodiment, the hydride in second fluid system 9 reacts with ahydride catalyst, preferably in first fluid system 12, where thecatalyst is configured to release the hydrogen in the hydride material.In one embodiment, production of hydrogen 20 is further assisted bygeothermal energy from formation 4. In a preferred embodiment, theinjected second fluid system 9 and first fluid system 12 are preferablyretained in subterranean formation 4 for at least 10 hours to allow theproduced hydrogen 20 to be released into fractures 18 in-situ. WhileFIG. 1 shows injection system 100 used with a vertical well, it isunderstood that injection system 100 is equally applicable to horizontalwells. Further, it is contemplated that injection system 100 can be usedto simultaneously inject second fluid system 9 and first fluid system 12into a plurality of strata having a plurality of perforated intervals.In the preferred embodiment where second fluid system 9 issimultaneously mixed with first fluid system 12, these fluid systems mixin well casing 1 and formation 4, causing the hydride in second fluidsystem 9 to react with additives in first fluid system 12, forminghydrogen 20. Because well casing 1 is closed off for a period of atleast 10 hours, subterranean formation 4 is held under pressure in thepresence of hydrogen 20. In other embodiments, the period of time can beabout 12 hours, about 18 hours, about 24 hours, more than 24 hours, morethan 36 hours, more than 48 hours, or more than 72 hours.

FIG. 2 shows a preferred embodiment of the effect of the processdescribed in FIG. 1. After the injection of second fluid system 9 andfirst fluid system 12 from blender truck unit 13 and injection pumptruck 16 is completed, well casing 1 is preferably sealed off to allowproduced hydrogen 20 to be retained and permeate formation 4. Referringto FIG. 2, in a preferred embodiment, well casing 1 is sealed off usingvalve 21 to seal where coiled tubing 6 was inserted and valve 22 to sealwhere first fluid system 12 from blender truck unit 13 was injected.When the hydride in second fluid system 9 reacts with additives in firstfluid system 12, hydrogen 20 is formed. Other suitable ways to isolatewell casing 1 known to those of ordinary skill in the art can be used.Sealing off of well casing 1 forces hydrogen 20 to permeate subterraneanformation 4 where it is absorbed by formation 4 and substances therein.In one embodiment, the absorbed hydrogen 20 displaces organic materiallike hydrocarbons, kerogen, and minerals from formation 4, which allowsthe organic material to flow to well casing 1 for production. In anotherembodiment, hydrogen 20 interacts with the organic material in formation4, transforming certain properties of the organic material, such ascausing it to expand, thereby increasing pressure and temperature information 4 and enhancing the mobilization of the hydrocarbonsubstances. Hydrogen 20 can easily flow from well casing 1 intoformation 4 because of its small atomic size. Further, the pressure andtemperature gradient created by the exothermic chemical reaction of thehydride with at least the additives in first fluid system 12 in forminghydrogen 20 facilitates the permeation of hydrogen 20 into formation 4and substances, preferably fluid substances, in formation 4. Thepressure in well casing 1 and/or subterranean formation 4 can be heldfrom the surface or below the surface.

FIG. 3 illustrates formation 4 from FIGS. 1 and 2 after hydrogen 20 hasbeen sufficiently retained, e.g., after the period of time of at least10 hours, and valve 22 is opened to release pressure and produce fluidsto the surface from formation 4, which include subterranean fluidsubstances like hydrocarbons and the injected first fluid system 12 andsecond fluid system 9. In one embodiment, valve 22 is opened to releasepressure and produce fluids. Opening of at least one valve, preferablyvalve 22, depressurizes fracture 18 and/or formation 4, creating a newpressure gradient out toward well perforations 3 for the escape anddepressurization of hydrogen 20 that permeated formation 4. Thedepressurization drives hydrogen out of the formation 4, thereby causingexplosive decompression of formation 4, which further creates cracks andrubblizing of formation 4 depicted by cloud like zones 24 alongfractures 18 and into formation 4. This depressurization is alsoreferred to as explosive decompression. Hydrogen 20's ability topermeate spaces, particularly small spaces in the micrometer andnanometer ranges, in formation 4 allows it to create more cracks information 4 to increase permeability formation 4 as a result ofexplosive decompression. The increased permeability, e.g., cracks, freesand/or creates additional paths to allow organic substances such askerogen, oil, and natural gas trapped in formation 4 to flow into wellcasing 1 through fractures 18 and perforations 3 and produced throughcasing 1 to the surface for commercialization. While the descriptionsherein relate to production of subterranean fluids, it is understoodthat subterranean substances can also be produced through physicalremoval of such substances through suitable means, such as those knownto be employed in mining operations.

It is understood that known aspects of hydraulic fracturing can be usedwith embodiments of the present invention. In one embodiment, pumping ofthe second fluid system 9 into the formation 4 can be done in stagesthroughout the hydraulic fracturing process. For instance, it can bedone prior to the gel stages comprising first fluid system 12 or afterthe gel stages which comprise proppant such as bauxite and sand. Certainembodiments of the present invention can be divided into multipleinjection stages of second fluid system 9 containing a hydride substancefollowed by multiple injection stages of first fluid system 12. Theseare merely exemplary orders of injections that are not meant to limitembodiments of the present invention.

FIG. 4 illustrates another embodiment to enhance production ofsubterranean substances, such as oil and gas in the field of enhancedoil production referred to those familiar with the art of oil and gasproduction as enhanced oil recovery (“EOR”). In one embodiment,production system 400 has injection well 420 and at least two productionwells 421. In a preferred embodiment, injection well 420 is placedbetween the at least two production wells 421. Preferably, eachinjection well 420 and production wells 421 comprises wellbore 402 withwell casing 401 disposed therein, where well casing 401 has perforations403 to allow fluid communication between surface 430 with formation 4through well casing 401. Injection well 420 further includes injectiontubing 405 disposed in well casing 401 of injection well 420. Productionwells 421 each preferably includes production tubing 406 disposed inwell casing 401 of the respective production well 421. In a preferredembodiment, at least one well, e.g., injection well 420 and/orproduction wells 421, further includes packer element 440 disposed nearthe open end of the respective tubing where either fluid is beingintroduced or fluid is being transferred out. Packer element 440 isplaced in the annular space between the respective tubing and therespective casing to help ensure the fluid is done only through therespective tubing, rather than into the annular space. In a preferredembodiment, packer element 440 can be used to release pressure from saidsubterranean formation. It is understood that embodiments shown in FIGS.1-3 can also include packer element 440 as appropriate.

According to another aspect of the present invention, first fluid 100 isinjected into injection well 420 down injection tubing 405. First fluid100 migrates into formation 4 through perforations 403. In a preferredembodiment, first fluid 100 comprises carbon dioxide. After a sufficientamount of first fluid 100 has been injected, second fluid 200 isinjected into injection well 420 through injection tubing 405. In apreferred embodiment, second fluid 200 comprises salt water. Secondfluid 200 also migrates into formation 4 through perforations 403. Aftera sufficient amount of second fluid 200 has been injected, third fluid300 is injected into injection well 420 through injection tubing 405.Third fluid 300 also migrates into formation 4 through well perforations403. In a preferred embodiment, third fluid 300 comprises a hydridesubstance, preferably a metal hydride substance. The successive stagesof injection of first fluid 100, second fluid 200, and third fluid 300migrate through formation 4 from injection well 420 toward bothproduction wells 421. As the successive stages of first fluid 100,second fluid 200, and third fluid 300 travel through formation 4, thefluids mix with one another. In the preferred embodiment, first fluid100 comprises carbon dioxide, and it has a pH of less than about 7.Second fluid 200 comprises salt water. Third fluid 300 comprises ahydride substance, preferably a metal hydride substance, and it has a pHof 7 or greater. These successive injection stages allow the low pHcarbon dioxide to mix with water forming carbonic acid, which thenreacts with the high pH hydride fluid system. The reaction between thecarbonic acid and hydride releases hydrogen and heat into formation 4,mobilizing and/or driving organic material such as oil, kerogen, andother materials in formation 4 toward production wells 421 and into wellcasing 401 of the respective production well 421 for production throughproduction tubing 406. In a preferred embodiment, fluids 100, 200, and300 are injected below fracture pressures of formation 4. It isunderstood that the descriptions of first fluid system 12 and secondfluid system 9 of FIG. 1 are equally applicable to fluids 100, 200, and300 of FIG. 4 as appropriate, for instance the additives and materialsthat can be added to first fluid system 12 and/or second fluid system 9can also be correspondingly added to fluids 100, 200, and 300 asappropriate. Another exemplary applicable aspect is the variousdescriptions of the hydrides, and particularly metal hydrides. Further,it is contemplated that certain embodiments disclosed herein can be usedto release hydrogen contained in the hydride substance, preferablyin-situ below the surface and preferably in a wellbore.

As described, embodiments of the present invention provide advantagesover other methods that use hydrides, such as that disclosed in U.S.Pat. No. 2,889,884. Such prior art method does not allow the hydrogen tobe retained in the subterranean strata. Further, this prior art methodneither transmits large amounts of the hydride far into the reservoirnor provide for sufficient mixing.

Although the present disclosure and its advantages have been describedin detail, it should be understood that various changes, substitutionsand alterations can be made herein without departing from the spirit andscope of the disclosure as defined by the appended claims. For example,the extraction of oil and gas from subterranean reservoirs is subset ofa larger field known as mining, and as such this disclosure has clearand obvious application to other fields of mining including but notlimited to the extraction of minerals and fluid other than hydrocarbons.Additionally, the methods and apparatus taught by this disclosure haveclear and obvious application in the field of hydrogenation of mineralsand fluids in-situ. Moreover, the scope of the present application isnot intended to be limited to the particular embodiments of the process,mineral extraction, fluid extraction, in-situ hydrogenation, machine,manufacture, composition of matter, means, methods and steps describedin the specification. As one of ordinary skill in the arts ofhydrocarbon extraction, water extraction, mining, and hydrogenation willreadily appreciate from the disclosure of the present disclosure,processes, devices, manufacture, compositions of matter, means, methods,or steps, presently existing or later to be developed that performsubstantially the same function or achieve substantially the same resultas the corresponding embodiments described herein may be utilizedaccording to the present disclosure. Accordingly, the appended claimsare intended to include within their scope such processes, devices,manufacture, compositions of matter, means, methods, or steps.

What is claimed is:
 1. A method for the extraction of at least onesubstance from a subterranean formation comprising: (a) injecting afirst fluid system into a subterranean formation through a wellbore at apressure sufficient to create at least one fracture in said subterraneanformation, wherein said subterranean formation is in fluid communicationwith said wellbore; (b) injecting a second fluid system into saidsubterranean formation through said wellbore, said second fluid systemcomprising a hydride substance; (c) mixing, in said wellbore, at least aportion of said first fluid system with at least a portion of thehydride material of said second fluid system to produce hydrogen; (d)retaining at least a portion of the produced hydrogen in saidsubterranean formation for a period of time of at least 10 hours; and(e) after said period of time of retention, producing at least onesubstance from said subterranean formation to the surface.
 2. The methodof claim 1 wherein the hydride substance preferably comprises a metalhydride substance.
 3. The method of claim 1 wherein the first fluidsystem and second fluid system are injected into said wellboresimultaneously.
 4. The method of claim 1 wherein said at least onesubstance is produced to surface through a wellbore.
 5. The method ofclaim 4 wherein said wellbore is the wellbore used for the injection ofsaid first fluid system and said second fluid system.
 6. The method ofclaim 1 wherein said first fluid system is injected into said wellboreusing a first conduit and said second fluid system is injected into saidwellbore using a second conduit separate from said first conduit.
 7. Themethod of claim 6 wherein said second conduit is disposed in said firstconduit through at least a portion of said wellbore.
 8. The method ofclaim 7 wherein said first conduit comprises a well casing and saidsecond conduit comprises a coiled tubing disposed in said well casing.9. The method of claim 1 wherein at least one of the first fluid systemand second fluid system has a pH less than about
 7. 10. The method ofclaim 1 wherein said second fluid system has a pH of about 7 or greater.11. The method of claim 1 further comprising heating the first fluidsystem to a temperature greater than the surface ambient temperatureprior to injecting it into the wellbore.
 12. The method of claim 1wherein the first fluid system comprises at least one of the following:steam, carbon dioxide, water, nitrogen, a hydride catalyst, a hydrideretarder, and any combination thereof.
 13. The method of claim 12,wherein the hydride catalyst comprises cobalt.
 14. The method of claim12 wherein the hydride retarder comprises a substance configured to coatthe hydride upon contact with said hydride substance.
 15. The method ofclaim 1 wherein the second fluid system has a pH of about 7 or greater,said second fluid system comprises at least one of the following: anammoniated fluid, ammonia hydroxide, and any combination thereof
 16. Themethod of claim 1, wherein the second fluid system comprises ahydrocarbon.
 17. The method of claim 1 wherein the second fluid systemcomprises a hydride reaction stabilizer.
 18. The method of claim 1wherein the first fluid system and second fluid system are alternativelyinjected into the wellbore.
 19. The method of claim 1, wherein the firstfluid system comprises a previously recovered subterranean fluidproduced from the subterranean formation.
 20. The method of claim 19wherein the previously recovered fluid comprises at least one of thefollowing: carbon dioxide, water, and any combination thereof.
 21. Themethod of claim 1 wherein at least one of said first fluid system andsecond fluid system contains at least one of the following: a proppingagent, a fluid viscosity modifier, a surface tension reducing agent, amicro-emulsion, and any combination thereof.
 22. The method of claim 21wherein said viscosity modifier is a gelling agent.
 23. The method ofclaim 22 wherein said gelling agent comprises a pH less than
 7. 24. Themethod of claim 21 wherein the respective fluid comprising the proppingagent has a pH less than about
 7. 25. The method of claim 1 wherein thesecond fluid system comprises an alcohol.
 26. The method of claim 1wherein the step of retaining a portion of said hydrogen comprisesretaining a portion of said hydrogen in said formation under pressure.27. The method of claim 26 wherein said pressure is held from thesurface.
 28. The method of claim 26 wherein said pressure is held frombelow surface.
 29. The method of claim 26 further comprising the step ofreleasing at least a portion of the pressure from said formation. 30.The method of claim 29 further comprises explosive decompression of saidformation in response to said releasing pressure step.
 31. The method ofclaim 1, wherein at least a portion of the hydrogen of said hydridereaction is produced to surface.
 32. The method of claim 1 wherein thehydride comprises at least one of the following: sodium borohydride,potassium borohydride, and lithium borohydride.
 33. The method of claim1 wherein the hydride comprises a solid substance.
 34. The method ofclaim 1 wherein the hydride fluid comprises a solution.
 35. The methodof claim 1 wherein the hydride comprises a blend of different hydrides.36. The method of claim 1 wherein the production of hydrogen is furtherassisted by geothermal energy from said formation.
 37. The method ofclaim 1 further comprising the steps of absorbing by said formation atleast a portion of said retained hydrogen; and in response to saidabsorption, desorbing at least one substance from said formation. 38.The method of claim 1, wherein said at least one subterranean substanceis produced through a second well bore separate from the well boreprovided for injection of said first and second fluid systems.
 39. Amethod to enhance the recovery of at least one subterranean substance bydecompressing at least a portion of a subterranean formation comprisinga) injecting at least one fluid system comprising a hydride substanceinto a subterranean formation through a wellbore, wherein saidsubterranean formation is in fluid communication with said wellbore; b)producing hydrogen in-situ from a chemical reaction of at least aportion of the hydride substance; c) retaining at least a portion ofsaid produced hydrogen in the subterranean formation for at least 10hours; d) increasing pressure of said formation at least through saidhydrogen production and retention; e) releasing at least a portion ofpressure from said subterranean formation; and f) recovering to surfaceat least one subterranean substance from said subterranean formationthrough a wellbore.
 40. The method of claim 39, wherein the at least onefluid system comprises at least one of the following: carbon dioxide,steam, nitrogen, carbon monoxide, and any combination thereof.
 41. Themethod of claim 39 further comprising injecting an additional fluidsystem into the wellbore prior to the step of injecting the at least onefluid system.
 42. The method of claim 41 wherein said additional fluidsystem is injected at a pressure above hydraulic fracture pressure. 43.The method of claim 39 further comprising injecting an additional fluidsystem into the wellbore after the step of injecting said at least onefluid system, wherein said additional fluid system is injected at apressure below hydraulic fracture pressure.
 44. The method of claim 43wherein the additional fluid system comprises at least one of thefollowing: an acid, carbon dioxide, an ammoniated fluid, steam, ahydride retarder, and any combination thereof.
 45. The method of claim44 wherein at least one of the at least one fluid system and additionalfluid system comprises a hydride catalyst.
 46. The method of claim 39wherein said pressure is released from the well allowing at least aportion of the in-situ generated hydrogen to flow out of saidsubterranean formation.
 47. The method of claim 39 wherein said pressurerelease is done rapidly from surface to force explosive decompression ofat least a portion of hydrogen in said subterranean formation.
 48. Themethod of claim 39 further comprising the step of placing a packer insaid wellbore at a position near where said at least one fluid system isintroduced to said subterranean formation, said packer is configured torelease at least a portion of pressure in said subterranean formation.49. A method of recovering at least one subterranean substance from asubterranean formation with hydrogen comprising; a) injecting, throughat least one conduit disposed in a first wellbore, at least a portion ofone fluid system from surface into a subterranean formation in fluidcommunication with said wellbore; b) injecting at least one additionalfluid system into said subterranean formation, said at least oneadditional fluid system comprising a hydride; c) releasing hydrogen insaid at least one additional fluid system by mixing said at least onefluid system with said at least one additional fluid system in-situ; d)allowing at least a portion of said hydrogen to enter said subterraneanformation; and e) recovering at least one substance contained in saidsubterranean formation to the surface through a second wellbore.
 50. Themethod of claim 49 wherein at least one fluid system comprises at leastone of the following: carbon dioxide, a hydride catalyst, a reactivesubstance configured to liberate hydrogen from said hydride substance,and water.
 51. The method of claim 49 wherein said fluid systems areinjected in alternating stages;
 52. The method of claim 49 wherein saidat least one fluid system has a pH of about 7 or less.
 53. The method ofclaim 49 wherein said at least one additional fluid system comprisinghydride has a pH of about 7 or greater.
 54. The method of claim 49wherein recovering back to surface said subterranean substancescomprises removing at least a portion of said subterranean formation andtransferring said portion to surface.
 55. The method of claim 49 whereinsaid at least one substance contained in said subterranean formationcomprises hydrocarbons.
 56. The method of claim 49 wherein said at leastone substance contained in said subterranean formation comprises atleast one rare earth substance.
 57. A method for the extraction of atleast one substance from a subterranean formation comprising: (a)injecting at least one fluid systems from the surface of the earththrough at least one conduit disposed in a first wellbore into asubterranean formation at a pressure sufficient to hydraulicallyfracture said subterranean formation; (b) injecting at least oneadditional fluid system comprising hydrogen; (c) exposing saidsubterranean formation to at least a portion of said hydrogen byretaining at least a portion of said hydrogen in said subterraneanformation for more than 10 hours; (d) releasing at least a portion ofpressure in said subterranean reservoir; and (e) recovering back tosurface at least one substance disposed in said subterranean formation.58. The method of claim 57 wherein said retaining at least a portion ofsaid hydrogen comprises holding at least a portion of said subterraneanreservoir under hydrostatic pressure.
 59. The method of claim 57 whereinsaid recovering step to surface is performed through at least one wellbore.
 60. The method of claim 57 wherein said recovering step isperformed through removal of at least a portion of said subterraneanformation containing said at least one substance.
 61. A method oftransforming in-situ at least one substance in a subterranean formationwith hydrogen comprising; a) injecting at least one fluid system throughat least one conduit disposed in a first wellbore into a subterraneanformation in fluid communication with at least said first wellbore; b)injecting at least one additional fluid system into said subterraneanformation, said at least one additional fluid system comprising ahydride; c) creating a reaction with said hydride to release hydrogencontained in at least a portion of said hydride; d) retaining at least aportion of said released hydrogen in said subterranean formation for atleast 10 hours; e) allowing at least a portion of said hydrogen totransform at least a portion of a substance contained in saidsubterranean formation; and f) producing to surface at least a portionof said transformed substance contained in said subterranean formation.62. The method of claim 61, wherein said producing step occurs through asecond wellbore.